Hydraulic fracturing is a term that has been applied to a variety of methods used to stimulate the production of fluids such as oil, natural gas, brines, etc., from subterranean formations. In hydraulic fracturing, a fracturing fluid is injected through a wellbore and against the face of the formation at a pressure and flow rate at least sufficient to overcome the overburden pressure and to initiate and/or extend a fracture(s) into the formation. The fracturing fluid usually carries a proppant such as 20-40 mesh sand, bauxite, glass beads, etc., suspended in the fracturing fluid and transported into a fracture. The proppant then keeps the formation from closing back down upon itself when the pressure is released. The proppant filled fractures provide permeable channels through which the formation fluids can flow to the wellbore and thereafter be withdrawn.
Hydraulic fracturing has been used for many years as a stimulation technique and extensive work has been done to solve problems present at each stage of the process. For example, a fracturing fluid is often exposed to high temperatures and/or high pump rates and shear which can cause the fluids to degrade and to prematurely "drop" the proppant before the fracturing operation is completed. Considerable effort has, therefore, been spent trying to design fluids that will satisfactorily meet these rigorous conditions.
High permeability formations such as those having permeabilities in excess of 50 millidarcy and particularly in excess of 200 millidarcy, present special challenges, especially when the reservoir temperature is above 130.degree. F. In these situations, the amount of fluid lost to the formation can be very high, resulting in increased damage and decreased fracture length. Further, the difference in permeability between the formation and the fracture is less than that realized in less permeable formations. Improved fracture cleanup is therefore necessary in order to maximize well productivity.
A wide variety of fluids has been developed, but most of the fracturing fluids used today are aqueous based liquids which have been either gelled or foamed. These fluids have typically been engineered for use in low permeability formations and are generally not well suited for use in higher permeability formations.
Aqueous gels are usually prepared by blending a polymeric gelling agent with an aqueous medium. Most frequently, the polymeric gelling agent of choice is a solvatable polysaccharide. These solvatable polysaccharides form a known class of compounds which include a variety of natural gums as well as certain cellulosic derivatives which have been rendered hydratable by virtue of hydrophilic substituents chemically attached to the cellulose backbone. The solvatable polysaccharides therefore include galactomannan gums, glycomannan gums, cellulose derivatives, and the like.
The solvatable polysaccharides have a remarkable capacity to thicken aqueous liquids, small amounts of these materials being sufficient to increase the viscosity of such aqueous liquids from 10 to 100 times or more. In some instances, the aqueous liquid thickened with polymers alone has sufficient viscosity to suspend the proppant during the course of the fracturing process and represents a satisfactory fracturing fluid. In other instances, principally in higher temperature applications, however, it is necessary to crosslink the polysaccharide in order to form a gel having sufficient strength and viscosity to retain the proppant in suspension throughout the pumping operation and placement in the subterranean formation. A variety of crosslinkers has been developed to achieve this result within different pH ranges.
The borate ion has been used extensively as a crosslinking agent for hydrated guar gums and other galactomannans to form aqueous gels used in fracturing and other areas. For example, U.S. Pat. No. 3,059,909 describes a crosslinked system which has been used extensively in the oil and gas industry as a fracturing fluid. A fracturing process which comprised crosslinking guar-containing compositions on-the-fly with a borate crosslinker is described in U.S. Pat No. 3,974,077. The borate crosslinked systems require a basic pH (e.g., 8.5 to 10) for crosslinking to occur. Borate crosslinked guar fluids, particularly fluids using less than 30 pounds guar per 1000 gallons of fluid have been used successfully in higher permeability formations up to a temperature of about 275.degree. F. With increased guar loadings, such fluids can be effective up to a temperature of about 350.degree. F.
Other crosslinking agents have been developed using certain transition metals. U.S. Pat No. 3,202,556, describes aqueous solutions of galactomannan gums which are crosslinked at a pH of from 5 to 13 with antimony or bismuth crosslinkers. U.S. Pat. No. 3,301,723, describes the use of certain titanium, zirconium, and other transition metals as crosslinking agents for galactomannans at a pH also in the range of from about 6 to about 13. In these patents, a basic pH is used to prepare crosslinked materials having utility in the explosives industry.
U.S. Pat. No. 3,888,312 describes the use of titanium crosslinkers with solvatable polysaccharides in fracturing fluids. The use of such crosslinked gels may act to overcome the high friction loss experienced during the pumping of many high-viscosity fracturing fluids previously known. U.S. Pat No. 3,301,723, also points out that crosslinked gels formed using titanium, chromium, iron and zirconium crosslinkers have a high surface tension i.e., stickiness and tackiness are absent, ready workability and other desirable physical characteristics.
A disadvantage associated with the above systems is related to the use of guar or guar derivatives as thickening agents. Such polymers are derived from natural sources, and usually contain insoluble materials that tend to remain in the formation or fracture after the fracturing treatment, and reduce the permeability of the formation or the fracture. Damage to the formation can be particularly important when the formation permeability exceeds about 100 mD. In such cases, whole fluid can penetrate the rock and fill the pore spaces. To minimize this problem, fracturing fluids have been developed that leave little or no residue.
Typical low-residue fluid systems comprise linear solutions of hydroxyethylcellulose (HEC). Like guar polymers, HEC is derived from natural sources; however, highly refined material is commercially available that is virtually free of insolubles. A potential problem with HEC is the formation of large incompletely hydrated lumps, also referred to as "fish eyes", and/or microgels during mixing. These insoluble materials result from poor dispersion of the HEC before the particles begin to hydrate, and the impact on formation and fracture permeability is as deleterious as the insoluble residue from guar polymers. In an attempt to avoid this problem, HEC fluids must commonly be sheared and filtered at the wellsite prior to pumping, thereby adding complexity and cost to its use, although this procedure is not 100% successful in addressing the problem.
The use of HEC-based fluids in fracturing applications is limited to use at formation temperatures of about 130.degree. to about 150.degree. F. As the temperature increases, the viscosity of these fluids decreases to nearly that of water, even for solutions having HEC loadings of 80 to 120 pounds per 1000 gallons of fluid. Above about 150.degree. F., the high leakoff rate inhibits or even prohibits the extension of the fracture. this is especially true in high permeability formations. As a result of the high HEC polymer loadings, large amounts of polymer are deposited in the formation which impair well productivity.
A different class of thickeners is described in U.S. Pat. No. 4,432,881, and identified as a superior fracturing fluid in U.S. Pat. No. 4,541,935. The thickener composition comprises a water soluble or water dispersible interpolymer having pendant hydrophobic groups chemically bonded thereto. When mixed with a water soluble or water dispersible nonionic surfactant, and a soluble electrolyte, a viscosified fluid stable to high temperature and/or shear is obtained. No problems with fish eyes or microgels are encountered, and conventional field mixing equipment can be used. The preferred interpolymers are vinyl addition polymers in which two or more vinyl monomers with ethylenic unsaturation are reacted together under polymerization conditions. Of these, polymers containing at least one of the water soluble monomers represented by Formula 1 or Formula 2 are preferred. ##STR1## R is hydrogen or methyl and Z is --NH.sub.2, --OH, --OR' where R' is a C.sub.1 -C.sub.4 alkyl group, --NH--R"--SO.sub.3 M wherein R" is an alkylene group of from 1 to 24 carbon atoms (preferably C.sub.1 to C.sub.4 alkylene) and M is hydrogen or an ammonium or alkali metal ion. ##STR2## R is hydrogen or methyl, X is --O-- or --NH--, and R is a hydrophobic group. R"' is preferably an aliphatic hydrophobic group such as an alkyl or alkenyl group of from 6 to about 24 carbon atoms or an inertly substituted such group, etc., and is most preferably an alkyl group of from about 8 to about 24 carbon atoms.
The interpolymers are usually solid polymers having a number average molecular weight of about one million or more.
The nonionic surfactant has a hydrophilic-lipophilic balance (HLB) of from about 10 to about 14. Such nonionic surfactants constitute a known class of compounds having many members. The preferred materials are ethoxylated alkanols having from about 8 to about 24 carbon atoms in the alkanol moiety. The preferred water soluble electrolytes are the sodium, potassium and ammonium halides.
Viscoelastic surfactants are employed as viscosifiers in the context of gravel packing fluids. Such systems contain virtually no insoluble residue. Gravsholt in "Viscoelasticity in Highly Dilute Aqueous Solutions of Pure Cationic Detergents," J. Colloid & Interface Sci. (57)3(1976), 575-77 indicates that certain quaternary ammonium salts impart viscoelastic properties to aqueous solutions. Gravsholt showed that cetyl trimethyl ammonium bromide would not impart viscoelastic properties to water but that cetyl trimethyl ammonium salicylate and certain other aromatic containing quaternary amines would. In U.S. Pat. No. 3,292,698, a mixture of cyclohexyl ammonium chloride and undecane-3-sodium sulfate was taught to induce viscoelastic properties to a formation flooding liquid containing less than about 3.5 percent by weight of sodium chloride. Higher levels of sodium chloride were said to destroy the viscoelastic properties of the fluid. UK Pat. No. 1,443,244, discloses a specific ethoxylated or propoxylated tertiary amine employed to thicken and aqueous solution of a strong mineral acid. U.S. Pat. No. 3,917,536 teaches that certain primary amines may be employed in subterranean formation acidizing solutions to retard the reaction of the acid on the formation. The amine may be more readily dispersed into the acid solution with the use of a dispersing agent such as a quaternary amine.
In particular Canadian Pat. No. 1,185,779, discloses a high electrolyte-containing aqueous wellbore service fluid which has improved viscosity characteristics over a wide range of wellbore conditions, including improved ease of preparation at the wellside and better shear stability and consistent viscosity over a wide temperature range. These improved aqueous wellbore service fluids are acknowledged as being useful in well known wellbore services such as perforation, clean-up, long term shut-in, drilling, placement of gravel packs and the like.